Techniques in the upstream oil and gas industry

ABSTRACT

CO 2  in the liquid or super-critical state is delivered by at least one carrier vessel from at least one CO 2  storage site, which may be an onshore site, to an integrated offshore facility. The integrated offshore facility is provided with at least one on-site storage tank or vessel adapted to store CO 2  in the liquid or super-critical state and with equipment for marine transfer of CO 2  in the liquid or super-critical state. CO 2  is utilised as required from said at least one on-site storage tank or vessel for EOR at said offshore site or for EGR at said offshore site by injection into a sub-sea oil or natural gas bearing reservoir and recovery of oil and/or natural gas from a resulting production stream.

CROSS REFERENCE TO RELATED APPLICATION

The present application claims priority to British Patent ApplicationNo: 1605615.2, filed with the UK Intellectual Property Office on Apr. 1,2016, the entire contents of which are incorporated herein by reference.

FIELD OF THE DISCLOSURE

This disclosure relates to the upstream oil and gas industry. Moreparticularly we disclose methods and apparatus for offshore CO₂-basedenhanced oil recovery (hereafter: “EOR”), or for offshore CO₂-basedenhanced gas recovery (hereafter: “EGR”).

BACKGROUND

EOR and EGR techniques of various kinds may be used to increase theproduction rates and recovery factors of oil or natural gas from areservoir. CO₂-based EOR or EGR techniques, in which CO₂ is injectedinto a reservoir, particularly one that is already significantlydepleted, have been proposed for use to enhance recovery of liquid orgaseous hydrocarbons, as have Water Alternating Gas (hereafter: “WAG”)techniques that employ injected water and gas, if appropriate, CO₂,alternately. WAG techniques employing CO₂ should be regarded as asub-set of CO₂-based EOR or EGR techniques.

While a number of onshore oil fields, particularly in the United Statesand Canada, have benefitted from CO₂ based EOR techniques, applicationof CO₂ injection to offshore oil and gas fields is more problematic, andhas necessitated a ready supply of CO₂ gas available through removal ofCO₂ from the hydrocarbon production stream.

The potential technical and economic benefits of CO₂-based EOR are wellpublicised, and could apply to CO₂-based EGR (See, for example:“Economic Impacts of CO2-Enhanced Oil Recovery for Scotland”, Pershad etal., July 2012, Element Energy Ltd and Heriot Watt University forScottish Enterprise). These include improved hydrocarbon productionrates—particularly in mature oil and natural gas fields, and improvedhydrocarbon recovery factors (the proportion of oil/gas in the reservoirthat it is technically and economically viable to produce).

However, application of CO₂-based EOR/EGR to offshore oil/gas fields hasbeen limited to date by a number of factors, which are further discussedbelow, namely:

-   -   Lack of availability of CO₂ offshore.    -   Variations in CO₂ quantities required through time.    -   Inability to match CO₂ supply and demand.    -   Difficulties with the application of CO₂ to existing production        facilities.    -   Limited remaining life of ageing assets.    -   Access of small and/or remote oil/gas fields to a CO₂ supply.

As a result of these issues, numerous opportunities for CO₂-basedEOR/EGR have been missed (both with respect to existing oil/gas assetsand new ones).

The quantity of CO₂ required to achieve viable enhanced hydrocarbonrecovery is significant, and has been estimated to be of the order of0.4 tonnes of CO₂ per barrel of incremental oil production [“TheEconomics of CO₂-EOR Cluster Developments in the UK Central NorthSea/Outer Moray Firth”, Prof. Alexander Kemp et al, Dept. of Economics,University of Aberdeen: North Sea Study Occasional Paper No: 123,January 2012]. Thus, for even a modest incremental oil production rate,the quantity of CO₂ required would be appreciable.

In order to make use of CO₂-based EOR/EGR, in addition to plant andequipment to inject the CO₂, the hydrocarbon production facility wouldneed the following:

-   -   Plant and equipment to separate the CO₂ from production streams        and to treat it as necessary.    -   Machinery to compress the ‘recycled’ CO₂ stream in preparation        for pumping and reinjection.    -   Acid gas capability to be in the material specifications etc.        throughout much of the facility.

For existing facilities, these will either be non-existent (nativehydrocarbon stream did not contain appreciable CO₂) or insufficient (waybelow the substantial handling capability required for CO₂-basedEOR/EGR). As a result, it has generally been considered that CO₂-basedEOR/EGR cannot be applied at an existing hydrocarbon facility withoutexpansive modifications and additions to the plant. Taking anincremental oil extraction rate of 30000 barrels per day, as an example,by Prof. Alexander Kemp et al's estimate supra, around 12000 tonnes ofCO₂ would be required per day. Once separated from the produced fluids,‘recycled’ CO₂ will be in the gaseous state. The design volumetric flowcapacities of plant, for example vessels and pipework, will have to takeaccount of this. In addition, compression machinery with the requisitecapability (driver power, pressure ratio and volumetric flow) will needto be in place. For the application of CO₂-based EOR/EGR to an existingoffshore asset, it is unlikely that the weight and footprint of all thenew plant required could be accommodated by the topsides of an existingfacility. It is possible that new jackets (for example: a newbridge-linked platform) or new floating facilities would have to beinstalled. Such capital-intensive modifications would quite likely makethe scheme unviable for older assets—more so for an asset in productiondecline.

CO₂-based EOR/EGR would theoretically be a particularly attractiveproposition technically for ageing oil/gas fields where production rateshave declined. However, while these techniques have the potential todefer end of field life, the asset life extension may be short whenviewed in the light of the capital expense of modifications andadditions that may be required to the existing facility as discussedabove. New plant installed on fixed jackets or fixed gravity basestructures together with the CO₂ transport pipelines would not be anattractive investment.

For a production facility that is small or remote, unless there isexisting CO₂ availability, the expenditure required for CO₂-based EOR orEGR is likely to be an unattractive prospect.

The transport of CO₂ to offshore hydrocarbon facilities by ship has beenpreviously considered [“Ship Transport of CO₂ for Enhanced OilRecovery-Literature Survey”, Dr Peter Brownsort, Scottish Carbon Capture& Storage, January 2015], but this study did not address importantissues that have a major effect on whether ship transport would providea viable alternative. In particular, the lack of any suggestion forproviding onsite CO₂ storage capability in Dr Brownsort's study, wouldmean that:

-   -   The rate of unloading CO₂ from the tanker would have to match        the required rate of injection of the supplied CO₂.    -   Hydrocarbon production would be vulnerable to interruptions in        the supply of supplied CO₂ which could result from something as        routine as delays in the CO₂ tanker schedule due to bad weather.

For all of the above reasons, heretofore CO₂-based EOR or EGR has notbeen seen as a financially viable prospect for offshore facilities.

SUMMARY OF THE DISCLOSURE

The teachings of the present disclosure aim to mitigate or overcomethese problems.

In accordance with a first aspect of this disclosure, a method isprovided for offshore CO₂-based EOR or for offshore CO₂-based EGR, inwhich method: CO₂ in a state selected from the liquid and super-criticalstates is delivered by at least one carrier vessel from at least one CO₂storage site to an integrated offshore facility provided with at leastone on-site storage means, selected from tanks and vessels, adapted tostore CO₂ in said state and with equipment for marine transfer of CO₂ insaid state; and CO₂ is utilised as required from said at least oneon-site storage means for EOR at said offshore site or for EGR at saidoffshore site by injection into a sub-sea oil or natural gas bearingreservoir and recovery of oil and/or natural gas from a resultingproduction stream.

It will readily be appreciated by persons skilled in this field that astorage tank adapted to store CO₂ in the liquid or super-critical statemust be a tank specific for this purpose and not just a conventional oilor natural gas storage tank that is re-utilised for CO₂.

According to a second and alternative aspect of this disclosure,apparatus for offshore CO₂-based EOR or for offshore CO₂-based EGRcomprises: an integrated offshore facility provided with:

at least one on-site storage tank or vessel adapted to store CO₂ in theliquid or super-critical state, and equipment for marine transfer of CO₂in the liquid or super-critical state,

equipment for injecting CO₂ into a sub-sea oil field for EOR or into asub-sea gas field for EGR; and

equipment for recovering oil and/or gas from a resulting productionstream;

and at least one carrier vessel adapted to deliver CO₂ in the liquid orsuper-critical state from at least one CO₂ storage site to the saidintegrated offshore facility.

The at least one CO₂ storage site is preferably an onshore site, but mayalso be or include an integrated offshore facility provided with atleast one on-site storage tank or vessel adapted to store excess CO₂derived from a production stream at said facility, the CO2 being storedin the liquid or super-critical state.

The integrated offshore facility may comprise one of a concretegravity-based structure located in fixed position by the ballastedweight of the structure resting on the seabed, and a steel gravity basedstructure in which the topsides are supported by a combined tank andsteel jacket which is located on the seabed by virtue of ballasted tankscapable of being emptied to allow the structure to be floated forrelocation; and the said on-site storage tanks adapted to store CO₂ inthe liquid or super-critical state are separate from any ballasted tanksand provided in the ballasted structure or mounted on the seabed.

Alternatively, the integrated offshore facility comprises a floatingstructure comprising one of (a) a floating production storage andoffloading structure in which a marine vessel has a hull and a deck, thehull being one of a ship-like shape and a generally cylindrical shapeand being provided with oil storage tanks therewithin for periodicoffloading of oil to an oil tanker, and the deck being provided withhydrocarbon processing equipment, (b) a floating natural gas structurehaving a hull and a deck, and comprising a vessel-based natural gasproduction facility provided with topsides plant comprising natural gasliquefaction plant on its deck and liquefied natural gas storage tanksin its hull for periodic offloading to a liquefied natural gas tanker,(c) a spar tethered to the seabed and comprising a deep verticallyoriented cylindrical section located below the waterline and a floatingplatform supported by the cylindrical section and comprising topsidesincluding oil production facilities, oil storage tanks being locatedwithin the vertical cylindrical section for periodic unloading to an oiltanker, (d) a semi-submersible structure comprising a buoyant platformprovided with ballasted tanks for oil or liquefied natural gas locatedbelow the waterline, the semi-submersible structure being tied to theseabed, and (e) a tension leg platform in which a buoyant platform islocated by mooring tethers in tension to ensure its vertical positionrelative to the seabed; and the said storage tanks adapted to store CO₂in the liquid or super-critical state are provided in the floatingstructure.

In a further alternative, the integrated offshore facility comprises ajack-up structure in which a barge type production platform providedwith legs and towed to a selected position is jacked up on the said legseither directly from the seabed or from a ballasted steel tank locatedon the seabed, and the said storage tanks adapted to store CO₂ in theliquid or super-critical state are provided in one of the barge and theballasted tank.

In a yet further alternative, the integrated offshore facility isprovided with a separate floating storage and offloading vessel withoutoil or gas production facilities, the vessel being provided with thesaid storage tanks adapted to store CO₂ in the liquid or super-criticalstate.

In other words, the integrated offshore facility may either be such afacility, such as an oil platform, in which the CO₂ storage tanks areintegrated into the facility proper (that is: the platform in thisexample) or a facility in which the CO₂ tanks are integrated into aseparate floating storage and offloading vessel. In a preferredembodiment of this arrangement, the separate vessel is provided bothwith plant and equipment which has the capability to process CO₂-ladenhydrocarbon production streams, separate CO₂ from production fluids, andprocess and apply the necessary pressure and temperature regulation toCO₂ so that it reaches the liquid or super-critical state; and withplant and equipment to achieve the requisite CO₂ pressure andtemperature for injection into the a sub-sea oil field or a sub-seanatural gas field. This arrangement enables EOR or EGR to be employed atan existing offshore facility not originally designed to use suchtechnology, and in particular such a facility with limited reservesand/or low production rates, and/or which is operating near to the endof its field life while avoiding capital expenditure on fixed structurethat would not be viable, thereby extending the life of or enhancing theproduction capacity of an otherwise largely depleted offshorehydrocarbon reservoirs as well as achieving a measure of carbonsequestration, and all without the need to install CO₂ transportpipelines. When no longer required, the separate floating storage andoffloading vessel may simply be towed away for use elsewhere.

Delivery of CO₂ to the integrated offshore facility by ship enables costlimiting factors relating to pipeline transport to be overcome. Storageof CO₂ on-site in storage tanks or vessels provided at the offshorefacility frees the carrier vessel from having to inject CO₂ directlytherefrom into the sub-sea oil or natural gas field at the rate and atthe time such injection is required, allowing more efficient use ofcarrier vessels, as transfer rates and timing for CO₂ transfer from thecarrier vessel is not dictated by the injection regime. In addition,since optimum conditions for injection differ from those associated withstorage and transport of CO₂, higher temperature and higher pressuregenerally being required, better results can be achieved if theinjection equipment is located at the off-shore facility rather than onthe carrier vessel, since CO₂ may be drawn from the storage tank orvessel on the offshore facility at the required rate and injected at thetemperature and pressure required. The capital cost of the carriervessel is also reduced. As compared with direct injection from thecarrier vessel, injection from storage tanks or vessels at the offshorefacility avoids injection interruptions and consequent interruption inoil or natural gas production resulting from stopping and startingproducing wells and other topsides plant and equipment, all caused bygaps between carrier deliveries or carrier delays due, for example, tobad weather.

Integrated offshore oil or natural gas facilities as defined above arebelieved novel and inventive in their own right. Accordingly, weprovide, in a third alternative aspect of this disclosure, an integratedoffshore oil or natural gas facility provided with:

at least one on-site storage tank or vessel adapted to store CO₂ in theliquid or super-critical state, with equipment for marine transfer ofCO₂ in the liquid or super-critical state,

equipment for injecting CO₂ into a sub-sea oil field for EOR or into asub-sea natural gas field for EGR; and

equipment for recovering oil and/or natural gas from a resultingproduction stream.

Preferably, the integrated offshore oil or natural gas facility isadditionally provided both with plant and equipment which has thecapability to process CO₂-laden hydrocarbon production streams, separateCO₂ from production fluids, and process and apply the necessary pressureand temperature regulation to CO₂ so that it reaches the liquid orsuper-critical state; and with plant and equipment to achieve therequisite CO₂ pressure and temperature for storage in said at least oneon-site storage tank or vessel or for injection into the sub-sea oilfield or the sub-sea natural gas field.

BRIEF DESCRIPTION OF THE DRAWINGS

Reference will now be made to the description of various embodiments byway of example only with reference to the accompanying drawings, inwhich:—

FIG. 1 is a schematic view of a plurality of onshore CO2 producers, arepresentative integrated offshore facility, and a plurality of carriervessels;

FIG. 2 is a schematic flow diagram for a system employing the teachingsof the present disclosure; and

FIG. 3 illustrates how different forms of offshore facility may beclassified.

DETAILED DESCRIPTION

An integrated offshore facility is schematically illustrated at 1 inFIG. 1. Distances are shown fore-shortened for ease of illustration. Inpractice, offshore oil and natural gas facilities are commonly locatedmany miles from the shoreline 2, especially in the North Sea. Theillustrated offshore facility is of the MOPU (Mobile Offshore ProductionUnit) type, linked by risers 3 to a plurality of sub-sea wellheads 4,but may take any of the conventional forms for offshore oil or naturalgas facilities as explained in more detail below. The floating unitillustrated incorporates at least one, and preferably a plurality of,storage tanks 5 for storing CO₂ in the liquid or super-critical statewithin hull 6 of the floating unit. One 7 a out of a fleet of carriervessels 7 is shown unloading liquid or super-critical CO₂ from thatvessel to the storage tanks 5 employing equipment 8 for marine transferof CO₂ in the liquid or super-critical state located on the floatingunit.

A plurality of onshore CO₂ producers 9, which may, for example, comprisepower stations or large industrial complexes, are associated with CO₂loading jetties 10 along the shoreline. The producers 9 may be soassociated by pipelines 11 for gaseous, liquid or super-critical CO₂and/or by other means of transport such as road or rail tankersoperating along rail or road networks between the producers 9 and thejetties 10 to transport CO₂ from the producer sites 9 to the jetties 10.

A fleet of CO₂ carrier vessels 7, enable simultaneous loading (shown bycarrier 7 b at jetty 10 a), transport from jetty to offshore facility(shown by carrier 7 c) and off-loading (shown by carrier 7 a) at theoffshore facility, so that a sufficient supply of CO₂ in liquid orsuper-critical state is always available at the offshore facility 1. Weenvisage that, in practice, there would be a large fleet of carriervessels 7 serving a number of offshore facilities 1. At or adjacent thejetties 10, storage tanks 12 are suitably provided, and these may beassociated with a plant for converting gaseous CO₂ delivered to thejetty facility into liquid or super-critical form before it is loadedinto the carrier vessels.

The offshore facility 1 is provide with equipment 13 for injecting CO₂into a sub-sea oil field for EOR, into a sub-sea natural gas field forEGR, or into a condensate field (being a field intermediate between anoil field and a natural gas field, in which an appreciable amount ofliquid is effectively present in vapour or fine droplet form within gas)for EOR and/or EGR.

Equipment 8 for marine transfer of CO₂ will be generally similar toequipment for marine transfer of oil or of liquefied natural gas, and nofurther details should be required for a person with skills in thesefields to select, purchase or fabricate suitable such equipment.Similarly, EOR and EGR are known techniques, and persons with skills inthese fields will be familiar with the kinds of equipment 13 requiredfor injecting CO₂ into a sub-sea oil field, into a sub-sea natural gasfield, or into a sub-sea condensate field. Similarly, equipment for theseparation of CO₂ from hydrocarbon production streams, and forsubsequent CO₂ treatment are also known per se. Accordingly, no detaileddescription of plant and equipment to separate and process CO₂, or toraise the pressure and regulate the temperature of the CO₂ to match therequired injection conditions, or of the associated technologies such ascompressors, pumps, coolers, or control systems, is deemed necessary.

The offshore facility may comprise one of many different structures, asexplained above, and as classified in FIG. 3. In accordance with theteachings of this disclosure, steel GBSs (Gravity Based Structures) withsteel tanks on the sea-bed, Jack-Ups with steel tanks on the sea-bed,Spars, FLNG (Floating Liquefied Natural Gas) structures, FPSO (FloatingProduction Storage and Offloading) structures, FSO (Floating Storage andOffloading) structures, and Concrete GBSs may be provided with equipmentcapable of marine transfer of CO₂ and with storage tanks suitable forstoring liquid or super-critical CO₂. Similarly, semi-submersibles maybe provided with tanks in their base capable of storage of liquid orsuper-critical CO₂. A separate floating storage vessel is suitablyprovided at the offshore facility when it is a Conventional Jack-Up, TLP(Tension Leg Platform), or Steel Jacket.

A separate vessel, not unlike that shown at 1 in FIG. 1, but tetheredalongside a pre-existing oil or natural gas facility (includingpreviously de-commissioned such facilities) is particularly suitablewhen that facility is one not originally designed to use CO₂-based EORor CO₂-based EGR technology, and in particular such a facility withlimited reserves and/or low production rates, and/or which is operatingnear to the end of its field life. By providing the separate vessel withequipment 8 for marine transfer of CO₂ as well as storage tanks forliquid or super-critical CO₂, with plant and equipment for processingCO₂-laden production streams, separation and treatment of separated CO₂,conversion of gaseous CO₂ to conditions required in readiness forinjection, and with equipment 13 required for injecting CO₂ into asub-sea oil field for EOR or into a sub-sea natural gas field for EGR,this avoids the need to provide such equipment 8 and/or equipment 13 onthe original offshore facility. When such new plant and equipment isprovided on a separate vessel, it will have acid gas capability whichmay not have been included in the specifications of the originaloffshore facility.

In the case of EOR or EGR in an existing oil or natural gas field,following an initial stage in which the sub-sea oil or natural gas fieldwill be charged with CO₂, CO₂ will emerge entrained in the oil ornatural gas produced from the field. Whether provided on the facilityitself or on the separate vessel discussed above and tethered alongsidethe original facility, plant and equipment 14 should also be providedwhich has the capability to process CO₂-laden production streams,separate CO₂ from the production fluids, and process and apply thenecessary pressure and temperature regulation to separated CO₂ so thatit reaches the liquid or super-critical state, and can be reinjectedinto the sub-sea oil or natural gas field together with such quantity offresh liquid or super-critical CO₂ supplied from the carrier vessels andstored in tanks on the facility itself or on the separate vessel, ifpresent, needed to make up the quantity of CO₂ required at any time.Equally well, CO₂ separated from production streams by appropriate plantand equipment of the kind employed in existing hydrocarbon productionfacilities utilising CO₂-based EOR or EGR may be employed to separateand process CO₂ from the production stream and pass it to the on-siteCO₂ storage tanks for injection at a later time. Such plant andequipment should be familiar to persons skilled in this field.Accordingly, no further detailed description of the separators,compressors, pumps, control systems, etc., employed in such plant andequipment is deemed necessary.

The United Kingdom and Norwegian sectors of the North Sea wouldparticularly benefit from the technologies disclosed herein. These areashave a number of mature fields whose yield of oil and natural gas isdeclining, but which have relative proximity to European countries withpower-intensive economies (many CO₂ sources) and numerous sea ports thatcan serve as CO₂ loading points. It will readily be appreciated that themethods herein described and the apparatus herein described, have theincidental benefit that, in operation, significant quantities of CO₂ issequestrated in the sub-sea reservoir.

The storage required at offshore facilities when the teachings of thepresent disclosure are applied is illustrated by the calculation below,by way of example.

As explained above, it has been estimated by Kemp et al that of theorder of 0.4 tonnes of CO₂ per incremental additional barrel of producedoil is required for EOR.

Reference may also be made to “A New Equation of State for CarbonDioxide Covering the Fluid Region from the Triple-Point Temperature to1100° K at Pressures up to 800 MPa”, Span et al, J. Phys. Chem. Vol 25,No: 6, 1996, for a discussion of the states of CO₂.

In the light of Kemp's estimate, for an incremental oil rate of 30000barrels per day, it would be necessary to inject 12000 tonnes/day ofCO₂. Liquid CO₂ typically has a temperature of −53° C., a pressure of7.5 bars absolute, and a density of 1166 kg/m³. Super-critical CO₂typically has a temperature of 37° C., a pressure of 80 bars absolute,and a density of 328 kg/m³. It can readily be seen from this that thedaily quantity of CO₂ required would occupy 10292 m³ in the liquid stateand 36585 m³ in the super-critical state.

Given the significant differences in density and required pressurebetween CO₂ in the liquid and super-critical states, storage in theliquid rather than the super-critical state has the advantage that thestorage vessels or tanks would not need to be so large or to bepressurised to so high an extent. Moreover, compliance with Health &Safety requirements would likely be less challenging. However,optimisation of design of the offshore facility with respect to cost,footprint, operability and availability may make it advantageous tostore at least some of the CO₂ in the super-critical state for at leastpart of the time. Accordingly, the “at least one on-site storage tank orvessel adapted to store CO₂ in the liquid or super-critical state”required by the present disclosure may encompass a variety of differentpossibilities, including: one or more tanks and/or vessels for storingliquid CO₂; one or more tanks and/or vessels for storing CO₂ in thesuper-critical state; and one or more tanks and/or vessels for storingliquid CO₂ as well as one or more tanks and/or vessels for storing CO₂in the super-critical state.

Long-term, a portion of the injected CO₂ will be made up of gas that waspreviously injected (‘recycled’ CO₂). This ‘recycled’ CO₂ will beentrained with the oil or natural gas produced, and, when separated,will be in the gaseous state. As well as treatment, it will requirecompression in preparation for pumping and reinjection.

Continuing with the aforesaid example, and considering two scenarioswhere 50% and 75% of the injected CO₂ is sourced from the productionstreams: The quantity of CO₂ that would have to be separated, treatedand compressed would be 6000 tonnes/day of CO₂ and 9000 tonnes/day ofCO₂, respectively. In volumetric terms, in the gaseous state, theseequate to 3.21 million standard cubic metres/day and 4.81 millionstandard cubic metres/day.

The plant capability required to handle the ‘recycled’ CO₂ stream istherefore notable. Unless the oil or natural gas facility was designedoriginally with a view to employing CO₂-based EOR or EGR, the plant andequipment required for acid gas handling, and the separation, treatment,compression and pumping of such quantities of gaseous CO₂ may best beprovided on a separate vessel designed for the purpose.

Reference will now be made to FIG. 2 to explain how the teachings of thepresent disclosure may be integrated within the functions of the overalloil/gas asset.

CO₂ is produced on-shore in step 15, and converted in step 16 to liquidor super-critical CO₂ either on-shore or on a carrier vessel. Carriervessels are loaded with CO₂ in step 17. CO₂ is transported by sea instep 18, and the vessel is coupled to an integrated offshore facility instep 19 for unloading of CO₂ in step 20. The empty carrier vessel isde-coupled in step 21, and returns to the same or another port in step22 to be recharged with CO₂. Liquid or super-critical CO₂ is stored instep 23 in tanks integrated into the facility proper, or in tanksintegrated into a separate vessel alongside and forming with thefacility proper an integrated facility. Liquid or super-critical CO₂ ispumped from store in step 24, and its temperature and pressure regulatedin step 25 before being injected in step 26 into injection wells.Production wells 27 pass fluids to produced fluids reception at 28, andthence to oil/gas/water/CO₂ separation and processing plant 29.Produced/recycled CO₂ passes from plant 29 to a further processing step30 and thence to production of liquid or super-critical CO₂ in step 31to pass to store 23 or alternatively direct to the pumping step 24 forreinjection. A produced natural gas stream from plant 29 passes viafurther processing and/or compression step 32 for direct export orliquefaction and on-site storage in step 33 or to a natural gas-basedsecondary recovery and/or EOR step 34 from which some or all of the gasis passed back to the production wells 27 to issue again in the producedfluids or is injected into the injection wells 26. A producedoil/condensate stream from the plant 29 passes to a further oil andcondensate processing step 35 and thence to direct export or on-sitestorage in step 36. A produced water stream from plant 29 passes to afurther water processing step 37 and thence either to disposal in step38 or to a water-based secondary recovery and/or EOR/EGR step 39 forinjection into the injection wells 26.

It should be understood by persons skilled in this field, withoutfurther explanation or detailed description, that in implementing theteachings of the present disclosure in practical offshore facilities,the following may be expected to be present:

-   -   Plant and equipment for the reception, separation and processing        of produced fluids.    -   Oil, condensate and natural gas storage and or export plant and        equipment.    -   In specific cases, equipment for the liquefaction, storage and        unloading of natural gas.    -   Machinery such as pumps, compressors and power-gen equipment.    -   Control systems.    -   Safety systems.    -   Offloading equipment.    -   Accommodation.

One of the most attractive applications of CO₂-based EOR/EGR is to agingassets and those in production decline. Therefore, while the teachingsof this disclosure are applicable both to new/planned and existingoffshore production facilities, their application to existing ones isworthy of particular consideration.

Persons skilled in this art will readily appreciate that the adoption ofmethods and apparatus employing the teachings of this disclosure willavoid many of the pre-existing problems preventing widespread use of EORand EGR techniques offshore.

There is no need to build a pipeline connecting an appropriately locatedonshore CO₂ source with offshore facilities using such CO₂ in CO₂-basedEOR/EGR.

There is no need to match the quantity and variability of CO₂ productionof the CO₂ ‘producer’ with the operational needs of the CO₂ ‘user’(offshore facility). For example, the production of CO₂ by a powerstation may vary due to grid demand (daily, seasonal), whereas an oilproduction facility tends to run at a constant rate.

The further complication that the amount of CO₂ which the oil/gasoperator may need to inject will likely vary through time—particularlyduring the formative stages of the application of CO₂-based EOR/EGR isalso avoided. This variability arises because, at the beginning of theprocess, the reservoir will need to be ‘charged’ with CO₂. During thistime the CO₂ being injected will be exclusively ‘supplied’ CO₂ from theonshore CO₂ producer. Later, previously injected CO₂ will be entrainedin the hydrocarbons produced. At least a proportion of this entrainedCO₂ may be separated, treated and re-injected. Consequently, as theproportions of ‘supplied’ and ‘recycled’ CO₂ in the injected CO₂ streamchange, the amount of ‘supplied’ CO₂ required will also change. Accurateforecasting of the time when CO₂-laden hydrocarbon streams reach theproducing wells (and the extent to which this will reduce the quantityof ‘supplied’ CO₂ required) is not possible. Consequently, heretoforethe setting up of future CO₂ purchase contracts would have beendifficult.

With such variability in the amount of ‘supplied’ CO₂ required by theoil/gas asset through time in addition to potential daily/seasonalchanges in the supplier's rate of CO₂ production, setting up equitablecontracts between CO₂ suppliers and oil/gas facility operators wouldhave been difficult. Heretofore, damping out differences between theproduction rates of specific CO₂ suppliers and the CO₂ quantitiesrequired by specific oil/gas facility operators could only have beenachieved by creating an expansive CO₂ pipeline grid connecting numerousCO₂ producers with numerous CO₂ consumers. However, to establish anexpansive CO₂ pipeline network would require a substantial capitalexpenditure. This would be both expensive and time-consuming.Furthermore, such high capital expenditure would be unlikely to proveeconomic in mature hydrocarbon basins like the North Sea where theremaining operating life of the offshore facilities, even with EGR/EOR,is likely to prove relatively limited.

The teachings of the present disclosure transform EGR/EOR, previouslyconsidered only a theoretical possibility for mature offshorehydrocarbon basins, into a realistically deployable technology with botheconomic potential for oil/gas recovery and the ability simultaneouslyto sequester significant quantities of onshore generated CO₂.

Although the present teachings are particularly useful in utilisingonshore generated CO₂, as described above, the same techniques can beemployed for utilising excess CO₂ present in the production stream froman offshore oil or natural gas facility, which would otherwise bedischarged to atmosphere or have to be piped elsewhere. CO₂ may bepresent in the production stream either because EOR/EGR was previouslyemployed at that facility or because the related subsea reservoircontains CO₂ as well as useful quantities of oil or natural gas. Theoffshore facility in question may not be suited to EOR/EGR and so haveno use for CO₂ entrained in its production stream. Alternatively, itsproduction stream may have more entrained CO₂ than needed for EOR/EGR atthat facility. In either such case, this second offshore facility servesas a CO₂ storage facility storing CO₂ in liquid or super-critical form,which can serve as a CO₂ source in a fashion similar to the previouslydescribed onshore sites. This CO₂ stored in the liquid or super-criticalstate may then be unloaded periodically to one or more carrier vesselsfor delivery to a separate integrated offshore facility such as thatillustrated at 1 in FIG. 1 at which the CO₂ is utilised for EOR or EGRin exactly the same manner as described above.

What is claimed is:
 1. A method for offshore CO₂-based EOR or foroffshore CO₂-based EGR, in which method: CO₂ in a state selected fromthe liquid and super-critical states is delivered by at least onecarrier vessel from at least one CO₂ storage site to an integratedoffshore facility provided with at least one on-site storage means,selected from tanks and vessels, adapted to store CO₂ in said state andwith equipment for marine transfer of CO₂ in said state; and CO₂ isutilised as required from said at least one on-site storage means forEOR at said offshore site or for EGR at said offshore site by injectioninto a sub-sea oil or natural gas bearing reservoir and recovery of oiland/or natural gas from a resulting production stream.
 2. A methodaccording to claim 1, wherein said at least one storage means includes aseparate floating storage and offloading vessel without oil or naturalgas production facilities provided at said integrated offshore facility,the said separate vessel being provided with said at least one storagetank adapted to store CO₂ in said state.
 3. A method according to claim2, wherein the said separate vessel comprises both plant and equipmentwhich has the capability to process CO₂-laden hydrocarbon productionstreams, separate CO₂ from production fluids, and process and apply thenecessary pressure and temperature regulation to CO₂ so that it reachesthe said state, and with plant and equipment to achieve the requisiteCO₂ pressure and temperature for injection into the a sub-sea oil fieldor a sub-sea natural gas field; whereby the said separate vessel may besupplied for CO₂-based EOR or for CO₂-based EGR at an offshore site nototherwise equipped for CO₂-based EOR or for CO₂-based EGR, and isadapted to be towed away from said site when no longer required thereatfor use at a fresh offshore site.
 4. A method according to claim 1,wherein the integrated offshore facility further comprises equipment forseparating CO₂ from the production stream for direct re-injection or forstorage in the at least one on-site storage means.
 5. A method accordingto claim 1, wherein the at least one CO₂ storage site comprises a secondintegrated offshore facility provided with at least one on-site storagemeans selected from tanks or vessels adapted to store CO₂ in said stateand with equipment for marine transfer of CO₂ in said state; the secondintegrated offshore facility having an oil/gas production streamincluding spare entrained CO₂ selected from CO₂ not required for use atthe second integrated offshore facility and CO₂ in excess ofrequirements for use at the second integrated offshore facility.
 6. Amethod according to claim 1, wherein the at least one CO₂ storage siteis at least one onshore site to which CO₂ is delivered by at least oneof pipeline, road and rail from at least one facility in which CO₂ isproduced as a waste product; and wherein the CO₂ is liquefied orrendered supercritical at one of the said facility and the onshore site.7. Apparatus for offshore CO₂-based EOR or for offshore CO₂-based EGRcomprising: an integrated offshore facility provided with: at least oneon-site storage means, selected from tanks and vessels, adapted to storeCO₂ in a state selected from liquid and super-critical states, andequipment for marine transfer of CO₂ in said state, equipment forinjecting CO₂ into a sub-sea oil field for EOR or into a sub-sea naturalgas field for EGR; and equipment for recovering oil and/or natural gasfrom a resulting production stream; and at least one carrier vesseladapted to deliver CO₂ in said state from at least one CO₂ storage siteremote from the integrated offshore facility, preferably an onshoresite, to the said integrated offshore facility.
 8. Apparatus accordingto claim 7, wherein the integrated offshore facility comprises one of aconcrete gravity-based structure located in fixed position by theballasted weight of the structure resting on the seabed, and a steelgravity based structure in which the topsides are supported by acombined tank and steel jacket which is located on the seabed by virtueof ballasted tanks capable of being emptied to allow the structure to befloated for relocation; and the said on-site storage tanks adapted tostore CO₂ in the liquid or super-critical state are separate from anyballasted tanks and provided in the ballasted structure or mounted onthe seabed.
 9. Apparatus according to claim 7, wherein the integratedoffshore facility comprises a floating structure comprising one of (a) afloating production storage and offloading structure in which a marinevessel has a hull and a deck, the hull being one of a ship-like shapeand a generally cylindrical shape and being provided with oil storagetanks therewithin for periodic offloading of oil to an oil tanker, andthe deck being provided with hydrocarbon processing equipment, (b) afloating natural gas structure having a hull and a deck, and comprisinga vessel-based natural gas production facility provided with topsidesplant comprising natural gas liquefaction plant on its deck andliquefied natural gas storage tanks in its hull for periodic offloadingto a liquefied natual gas tanker, (c) a spar tethered to the seabed andcomprising a vertically oriented cylindrical section located below thewaterline and a floating platform supported by the cylindrical sectionand comprising topsides including oil production facilities, oil storagetanks being located within the vertical cylindrical section for periodicunloading to an oil tanker, (d) a semi-submersible structure comprisinga buoyant platform provided with ballasted tanks for oil or liquefiednatural gas located below the waterline, the semi-submersible structurebeing tied to the seabed, and (e) a tension leg platform in which abuoyant platform is located by mooring tethers in tension to ensure itsvertical position relative to the seabed; and wherein the said storagetanks adapted to store CO₂ in said state are provided in the floatingstructure.
 10. Apparatus according to claim 7, wherein the integratedoffshore facility comprises a jack-up structure in which a barge typeproduction platform provided with legs and towed to a selected positionis jacked up on the said legs directly from the seabed or from anoptional ballasted steel tank located on the seabed, and the saidstorage tanks adapted to store CO₂ in said state are provided in one ofthe barge and the optional ballasted tank.
 11. Apparatus according toclaim 7, wherein the integrated offshore facility is provided with aseparate floating storage and offloading vessel without oil or naturalgas production facilities, the vessel being provided with the saidstorage tanks adapted to store CO₂ in said state.
 12. Apparatusaccording to claim 11, wherein the separate vessel comprises both withplant and equipment which has the capability to process CO₂-ladenhydrocarbon production streams, separate CO₂ from production fluids, andprocess and apply the necessary pressure and temperature regulation toCO₂ so that it reaches said state; and with plant and equipment toachieve the requisite CO₂ pressure and temperature for storage in saidat least one on-site storage means or for injection into the sub-sea oilfield or the sub-sea natural gas field.
 13. Apparatus according to claim7, wherein the integrated offshore facility additionally comprises bothplant and equipment which has the capability to process CO₂-ladenhydrocarbon production streams, separate CO₂ from production fluids, andprocess and apply the necessary pressure and temperature regulation toCO₂ so that it reaches said state; and with plant and equipment toachieve the requisite CO₂ pressure and temperature for storage in saidat least one on-site storage means or for injection into the sub-sea oilfield or the sub-sea natural gas field.
 14. An integrated offshore oilor natural gas facility comprising: at least one on-site storage means,selected from tanks and vessels, adapted to store CO₂ in a stateselected from liquid and super-critical states, and equipment for marinetransfer of CO₂ in said state, equipment for injecting CO₂ into asub-sea oil field for EOR or into a sub-sea natural gas field for EGR;and equipment for recovering oil and/or natural gas from a resultingproduction stream.
 15. An integrated offshore oil or natural gasfacility according to claim 14, additionally comprising both with plantand equipment which has the capability to process CO₂-laden hydrocarbonproduction streams, separate CO₂ from production fluids, and process andapply the necessary pressure and temperature regulation to CO₂ so thatit reaches said state; and with plant and equipment to achieve therequisite CO₂ pressure and temperature for storage in said at least oneon-site storage means or for injection into a sub-sea oil field or asub-sea natural gas field.